Coterra Energy Inc. (NYSE:CTRA) Q3 2025 Earnings Call Transcript

Coterra Energy Inc. (NYSE:CTRA) Q3 2025 Earnings Call Transcript November 4, 2025

Operator: Thank you for standing by. At this time, I would like to welcome everyone to today’s Coterra Energy Third Quarter 2025 Earnings Call. [Operator Instructions] I would now like to turn the call over to Dan Guffey, Vice President of Finance, Investor Relations and Treasurer. Dan?

Daniel Guffey: Thank you, Greg. Good morning, and thank you for joining Coterra Energy’s Third Quarter 2025 Earnings Conference Call. Today’s prepared remarks will include an overview from Tom Jorden, Chairman, CEO and President; Shane Young, Executive Vice President and CFO; and Michael Deshazer, Executive Vice President of Operations. Blake Sirgo, Executive Vice President of Business Units, is also in the room to answer questions. Following our prepared remarks, we will take your questions during our Q&A session. As a reminder, on today’s call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures were provided in our earnings release and updated investor presentation, both of which can be found on our website.

With that, I’ll turn the call over to Tom.

Thomas Jorden: Thank you, Dan, and thank you to all who are listening this morning. Coterra had a strong third quarter and is on track to deliver on the ambitious annual goals that we set for ourselves for the full year 2025. Furthermore, we released a soft guide to our coming 3-year plan update that shows that we remain committed to a long-term path of consistency, profitable growth and value creation for shareholders. I want to give a shout out to our field and office personnel who have worked valiantly to deliver results as promised and to do so safely with environmental integrity and with a relentless focus on maximizing full-cycle returns. We could not be prouder of our organization and their commitment to excellence. We delivered on all fronts during the third quarter.

Our volumes on gas, oil and barrel of oil equivalent came in above the midpoint of our guidance. We delivered outstanding returns on invested capital with great capital efficiency. The integration of the Lea County assets that we acquired early in the year has gone well, and we are realizing significant uplifts in asset performance, cost reductions and future inventory. Michael Deshazer will provide further details here. We plan to deliver a comprehensive updated 3-year outlook with our fourth quarter release in February. Last night, however, we provided an early look into 2026, which demonstrates our multiyear commitment to growing revenue, cash flow, free cash flow and profitability. As we see it today, we expect capital to be modestly down year-over-year while still achieving consistent profitable growth.

Our low breakevens and deep inventory, coupled with our balanced revenue between gas and oil assets provides the opportunity to deliver through the cycles and maintain a degree of consistency that differentiates us. We view our future entirely through a lens of increasing shareholder value, and we best achieve this by consistently making smart full-cycle investments through the commodity swings. I do want to emphasize that we are providing a soft guide for 2026, and final decisions are a work in progress. We are watching markets carefully. Oil markets have a lot of moving pieces. These include the timing and impact of Russian sanctions, the situation in Venezuela, Chinese and Indian behavior and global economic robustness. While we have the projects and wherewithal to further increase our oil growth, if warranted, we are remaining disciplined and not chasing growth in the current environment.

Although capital may modestly flex up or down each year, our sole goal is to consistently grow our profitability and maximize our free cash flow. We are living in rapidly changing times. The increase in LNG exports and growing electricity demand is constructive for the medium- and long-term outlook for natural gas. We are prepared to be patient and not front-run demand increases. Our marketing group is heavily engaged in discussions with counterparties seeking new natural gas supply arrangements to further diversify our portfolio, which already has committed 200 million cubic feet a day to recently announced LNG deals, 350 million cubic feet per day to Cove Point LNG, 50 million cubic feet per day power — Permian power deal with CPV and our 320 million cubic feet per day of natural gas supply deals to local power plants within the Marcellus.

While these deals total approximately 30% of Coterra’s gas production, the team continues to bring fresh ideas to the table to further improve and diversify our portfolio. Our marketing team has a mandate to generate value, not press releases. We are confident that patience is prudent and that the future of natural gas will provide tremendous opportunities for Coterra. There is a lot happening under the hood. We are also watching all markets carefully, as I said, the swing between optimism and pessimism here is remarkable. A tiny change in facts can drive huge swings in emotion. Coterra has a deep inventory of oil assets with one of the lowest breakeven portfolios in our sector. Our bias is steady as she goes without wild reactive swings. Before I turn the call over to Shane, you will note that Michael Deshazer will be delivering the operational summary today.

Blake Sirgo is with us and will undoubtedly have the opportunity for comments. We recently switched the portfolios of Blake and Michael, with Blake assuming oversight over our business units and Michael taking on our operational and marketing portfolios. This change was entirely driven by a desire to build redundancy in our skill sets and build broader depth of expertise on the executive team. We have a highly collaborative executive team that, by design, is broadly familiar with all aspects of our business. This change will further increase our flexibility, bring fresh eyes on critical issues and provide an ability for both Michael and Blake to enlarge their impact. Every now and then, it is good to repot the plant. Finally, we know that many of you have seen the letter that Kimmeridge released this morning.

Although we think that it contains some factual errors, we have great respect for many of the thought pieces that the Kimmeridge team has produced over the years and have had constructive engagement with them in the past. We are disappointed that they have chosen to release a public letter without reaching out to us. Nonetheless, we are open to suggestions that can improve Coterra. And as always, we will listen, carefully consider ideas and be thoughtful in our response. With that, I will turn the call over to Shane for a financial summary.

Shannon Young: Thank you, Tom, and thank you, everyone, for joining us on this morning’s call. Today, I’d like to cover 3 topics. First, I will quickly summarize a few key takeaways from our strong third quarter financial results. Then I’ll provide our fourth quarter guidance and update to our full year 2025 guidance. Finally, I’ll provide comments on our balance sheet and cash flow priorities for the remainder of the year. Turning to our performance during the quarter. Performance in all 3 business units exceeded expectations during the third quarter. Coterra’s oil, natural gas and BOE production each came in approximately 2.5% above the midpoint of our guidance. Additionally, NGL production was strong, posting an all-time high for Coterra at around 136 MBoe per day.

In the Permian, we had 38 net turn-in-lines during the quarter, just below the low end of our guidance range, while the Anadarko and Marcellus had net turn-in-lines of 6 and 4, respectively, in line with expectations. We continue to expect TILs in all areas to be within our annual guidance ranges with the Permian being near the high end of the range. Pre-hedge oil and gas revenues came in at $1.7 billion with 57% of revenues coming from oil production. This is up sequentially from 52% in the prior quarter and was driven by a substantial uptick in oil volumes of 11,300 barrels per day, an increase of above 7% above our second quarter levels. The Permian team continues to drive outstanding incremental production results. Cash operating costs totaled $9.81 per BOE, up 5% quarter-over-quarter due to production mix and higher workover activity, which we expect to moderate during the fourth quarter.

Incurred capital in the third quarter were near the midpoint at $658 million. Discretionary cash flow for the quarter was $1.15 billion and free cash flow was $533 million after cash capital expenditures. Both of these figures benefited from negative current taxes for the quarter related to recent changes in U.S. tax law. In summary, our strong third quarter results show continued improvement in capital efficiency as production exceeded expectations and capital remains on track. We continue to run a consistent and highly efficient activity cadence, which we expect will continue to generate strong full-cycle returns in the current price environment. Looking ahead to the fourth quarter and the full year 2025. During the fourth quarter of 2025, oil production is expected to be 175 MBoe per day at the midpoint, an increase of over 8,000 barrels per day or another 5% increase quarter-over-quarter.

We expect total production to average between 770 and 810 MBoe per day and natural gas to be between 2.78 and 2.93 Bcf per day. We expect capital for the quarter to be around $530 million, significantly below the third quarter results as we wrapped up frac activity in the Anadarko late in the third quarter. For full year 2025, we are increasing annual MBoe per day production guidance to 777 at the midpoint, a 5% increase from our initial guidance in February. We are maintaining the oil guidance midpoint at 160 MBoe per day while tightening the guidance range. Oil volumes from our acquired assets have been in line to slightly better than expected. Our legacy assets oil volumes are expected to deliver a high single-digit percentage growth rate year-over-year.

This is similar to the rate of growth we have delivered during the prior 3 years. On natural gas, we are increasing the midpoint of our volume range to 2.95 Bcf per day, an increase of over 6% from our initial full year guidance in February. As previously indicated, we expect capital for the year to be approximately $2.3 billion, just above the midpoint of our initial guidance range in February as we have maintained the second Marcellus rig into the second half of the year. Our annual expense guidance ranges remain unchanged, and we expect to be near the midpoint of the aggregate expense range for the full year. With regard to our 3-year outlook provided in February, we remain highly confident in our ability to deliver results within those ranges from 2025 through 2027.

This outlook is underpinned with a low reinvestment rate and improving capital efficiency and delivers attractive long-term value creation for our shareholders. While we are not prepared to provide specific 2026 guidance, a current snapshot suggests that capital should be down modestly year-over-year while still maintaining production parameters laid out in our 3-year guide we released in February. At the same time, our low breakevens, low leverage and operational flexibility, coupled with our hedge book, have Coterra well positioned in the event of high commodity price volatility in 2026. Turning to shareholder returns and the balance sheet. For the third quarter, we announced a dividend of $0.22 per share. This is one of the highest-yielding dividends in the industry at over 3.5% and demonstrates our confidence in the long-term durability, depth and quality of our future inventory and free cash flow.

Additionally, during the third quarter, we repaid $250 million of outstanding term loans that were used as part of the financing of our acquisitions earlier this year, bringing our total term loan pay down to $600 million through the third quarter of 2025. In October, based on the progress we have made in retiring our term loans and the trading levels of our shares, we reinitiated our share buyback program. While we continue to make progress on our debt retirement goals during the fourth quarter, we’ll be opportunistic in purchasing our shares. We ended the quarter with an undrawn $2 billion credit facility and a cash balance of $98 million for total liquidity of $2.1 billion. As of September 30, we had total debt outstanding of $3.9 billion, down from $4.5 billion at the closing of the acquisitions in January.

We’re making meaningful progress in executing on our priority of getting our leverage back to around 0.5x net debt to EBITDA. Coterra remains committed to maintaining a top-tier fortress balance sheet that is strong in all phases of the commodity cycle. We believe this enables us to take advantage of market opportunities while protecting our shareholder return goals. In summary, Coterra’s team delivered another quarter of high-quality results across all 3 business units. We continue to enhance capital efficiency through higher productivity and lower cost per foot completed. Our consistent activity has continued to deliver meaningful oil production growth throughout the year while raising the bar on both natural gas and BOE production. In 2025, we expect to generate substantial free cash flow of around $2 billion, an approximately 60% increase over 2024, benefiting from both higher natural gas realizations and higher oil volumes from our acquired assets.

While we continue to prioritize deleveraging, we see significant value in Coterra at current share prices and are approaching buybacks opportunistically. In summary, Coterra has never been stronger or better positioned. With that, I will hand the call over to Michael to provide additional color and detail on our operations.

Michael Deshazer: Thank you, Shane. Today, I will talk about our third quarter operational results and outlook. We’ll provide a business unit update, including the successful integration and upside to our Franklin Mountain and Avant acquisitions, and I will briefly touch on our marketing efforts. The third quarter was another well-executed quarter, and we carried this operational momentum into the fourth quarter. On the activity front, we have a consistent 9-rig, 3-crew program working in the Permian, 1 rig and 1 crew in the Marcellus and 1 rig in the Anadarko. We expect to maintain this activity level during the fourth quarter. To reiterate what Shane touched on earlier, looking ahead to 2026, we expect 2026 capital to be down modestly year-over-year, while still achieving the production ranges laid out in our 2025 through 2027 3-year outlook.

While we are focused on consistent operations through the commodity cycles, we are maintaining maximum operational flexibility with no rigs or frac crews on long-term contracts. We expect to provide a comprehensive 2026 guidance and an updated 3-year outlook in February. The integration of our Franklin Mountain and Avant assets is complete, and our teams continue to outperform our expectations for synergies on these assets. I would like to spend a few minutes discussing our progress. When we announced the acquisition, there were many wells that were in various stages of development, and we made estimates of their productivity for our evaluation and for our full year production guidance. In November 2024, we announced a 2025 production estimate for the assets of 40,000 to 50,000 barrels of oil per day, assuming a full year contribution.

When we updated our production guidance on our February call after the actual close dates in late January of the assets were known, we maintained our annual production guidance because we liked how the assets were performing. I am pleased to report that we continue to perform in line to above our production expectation for the acquired assets, giving us further confidence that there is upside relative to what was underpinned — what underpinned the acquisition. On the capital side of the acquisition, we have realized a 10% reduction in our total well costs as measured in dollars per foot by applying our Coterra best practices at scale across the assets. A few of the efficiencies I would like to point out are our optimized and standardized hole size and casing designs, which have reduced our drilling times from 15 to 13 days for a standard 2-mile lateral.

And on the completion front, we have seen that implementing our proven stimulation designs that have been evaluated across the basin and tailored for each landing zone as well as our scale in the Permian has allowed us to reduce service costs. In addition to capital savings, we now have line of sight to significant operating cost synergies. We have already reduced the inherited lease operating expense by approximately 5% or $8 million per year. These savings have been seen across most services, but the biggest savings are related to on-pad sour gas treating and electric generation. For example, at our Eagle central tank battery, we acquired a facility that treated sour gas to then be burned in gas turbines to generate power for our field. Working with our marketing team, we accelerated a residue gas connection to the site that allowed us to remove the gas-treating equipment and allow the turbines to burn clean low Btu gas, increasing reliability and saving over $2.5 million per year in expenses.

There are many more projects like this one, and we are currently projecting an additional $20 million per year in net operating cost savings related to on-pad sour treatment, taking our projected total LOE savings on the acquired assets to 15% as a go-forward run rate. In addition, we believe that the biggest future savings could come from using microgrids instead of well-site generators to power our assets. We are in the final stages of planning for up to 3 microgrids across our Northern Delaware Basin assets. We think that these projects will have the potential to reduce our current power costs by 50%, saving an additional $25 million a year. But as the asset and our power demand in the area grows, the projected savings will grow as well to nearly $50 million per year.

This is all while we continue to work with our utility power providers to bring more grid power into the Permian Basin. Now that we have integrated the assets, we expect not only to demonstrate capital and expense reduction, but also productivity enhancements as we pursue a development plan focused on maximizing capital efficiency. Our subsurface teams have continued to delineate multiple landing zones, and this work has given us confidence that we have 10% more inventory as measured by net lateral footage than we estimated when acquiring the assets. Furthermore, our increased scale in the Northern Delaware Basin has enabled us to make many value-added trades and small-scale acquisitions. We expect our team to prudently add valuable inventory as we continue to develop our highly profitable and low-cost resources in the Permian Basin.

Moving on to the Marcellus business unit. This quarter, we drilled a new 4-mile lateral from spud to rig release in under 9 days, averaging 2,400 feet per day. This sets a new high watermark for Coterra. In fact, it’s becoming common for many of our recent wells to eclipse 2,000 feet per day. This type of performance and longer laterals reaching over 20,000 feet have driven drilling costs down 24% year-over-year. With these efficiencies, we no longer need 2 rigs to maintain production in our Marcellus asset. Our maintenance activity level over the next few years would require 1 to 2 rigs, so we will manage our rig count to not build excessive DUC backlog. While we hold the option to grow our Marcellus natural gas volumes, we are committed to being patient and expect to hold our production volumes relatively flat until additional demand materializes and the strip solidifies.

Should we have a cold winter and prices increased into ’26, we will fully participate from our approximately 2 Bcf a day of production in the Northeast and expect to generate substantial free cash flow from our Marcellus region. In the Anadarko business unit, we brought online our last project of the year during the third quarter, the 5 3-mile Hufnagel wells. These new wells, combined with our Roberts project from Q2, continue to drive strong region performance that has exceeded our expectations. Turning to marketing. Our team continues to be active in the hunt for more deals and partnerships that can deliver flow assurance and price uplift for our products across our diverse portfolio. As Blake mentioned last quarter, the long-term gas sales to CPV’s new Basin Ranch power plant in Reeves County, Texas was the latest in a line of deals that our company has a history of delivering.

As Tom mentioned, our Moxie and Lackawanna power deals in the Marcellus were put in place 10 years ago and have provided value well and above an in-basin price. We will continue to find opportunities to improve the netback of our product and increase the value to our shareholders. A strength of our sales portfolio is a significant diversification, but we are not satisfied and we’ll continue to optimize. The teams in all 3 of our regions are firing on all cylinders and have remained focused on solid execution, making decisions to maximize full-cycle returns and creating value for shareholders. With that, I’ll turn the call back over to the operator for Q&A.

Q&A Session

Operator: [Operator Instructions] It looks like our first question today comes from the line of Doug Leggate with Wolfe Research.

Douglas George Blyth Leggate: Tom, as always, you’re very gracious to hit the 800-pound gorilla right in the head with the comments around the Kimmeridge letter. So I wonder if I could just ask you to elaborate on your perspective this morning. The — I guess the way I would phrase it is that when you look at the gas-levered E&Ps, particularly your larger peers, EQT and Expand and compare your relative performance, it almost seems like you’ve been kind of orphaned by the mix of your portfolio. And I guess the basis of the Kimmeridge letter is you’re better as a stand-alone pure play in the Delaware and let someone else take care of the gas. That would go 180 degrees against what you tried to build. How would you respond to that?

Thomas Jorden: Well, first off, Doug, I don’t want to get into a lot of discussion about the Kimmeridge letter. That’s for another time. But we’ve spoken openly. We really believe Coterra is a premier outfit, and we like to see us trade at a premium multiple. But if you look at the trading over the last year, you’ll find [ we’re ] at the top of the stack of oil companies and at lower level of gas companies. And we think we’re seeing benefits of it being a multi-basin, multi-commodity company. But I just think it would be inappropriate for me to get into any more than that, Doug.

Douglas George Blyth Leggate: Okay. I understand, and I appreciate you taking a stab at it. My follow-up is an operational question, and it’s really related to what you saw in your LOE this quarter. Obviously, it’s still elevated, but you also beat on your oil guidance. So my question is, is this related to the workovers in the Harkey? Should we continue to expect your oil production to move up and then ultimately your LOE to move down as those workovers flow through the system?

Michael Deshazer: Yes, Doug, this is Michael. Yes, the LOE for the quarter was up a little bit. We have transitioned out of the Harkey remediation program that we talked about last quarter, and we have moved workover rigs into Lea County, where we do have some higher working interest. But overall, we do expect our LOE costs, especially the workover costs to decrease as we head into Q4.

Shannon Young: Yes. And Doug, Shane here. Just — we do expect that number to settle for the year within range on the LOE and expect to be probably in the middle in terms of total cash cost of where we are as well. But Michael hit on really well sort of the reason why it looked a [ touch up ] in the third quarter.

Operator: And our next questions come from the line of Betty Jiang with Barclays.

Wei Jiang: I want to ask about the cash return strategy just because we would agree that the stock, it does look discounted in our view as well. Shane, last quarter, you talked about really focusing on debt reduction. And then this quarter, Coterra is starting the buyback program again. How do you think about the allocation of your excess free cash flow between debt reduction and buyback going forward? Is there a reason not to think we can get back to that 100% return level into next year?

Shannon Young: Yes, Betty, Shane here. Thanks for the question. And as you noted, year-to-date, we prioritized deleveraging or paying off the term loans. And so that’s why we leaned in really hard in the third quarter on that. It’s interesting. When you’re at sort of the last bit of the repayment, your feeling is a little different than when you’re at the first bit of the repayment and the ability to sort of feather in both some buyback activity and continued deleveraging is just much more palatable at these states. So as we talked about, we reinitiated the program in this month and — sorry, last month and expect that we’ll continue to be opportunistic, particularly where prices have been over the course of the last 4 to 6 weeks.

In terms of the future levels that we get to, look, I would only say, look at our past. And in 2024, we returned roughly 94% of free cash flow through the mix of dividend and buybacks. And the year before that, I think we’re around 75% in 2023. And look, that’s a place we strive to get back to and think we’re well on our way to being there. Is that exactly what it looks like in 2026? We’re not going to pin ourselves in. But I think we’ll have a robust return of capital program in 2026.

Wei Jiang: That’s great. And my follow-up is on the overall activity in the Permian. If we look at the Delaware versus your initial expectations, production is — the guidance is unchanged, while you are now completing wells toward the upper end of the guidance range. I’m just wondering relative to your internal expectations, how is the production profile on the wells tracked versus your initial guide. And with activity now towards the high end, does that change your views on how the shape of 2026 shake out?

Shannon Young: Betty, Shane here. I’ll take a stab at that. I mean we don’t comment specifically on TIL timing within quarters, but we do give how many TILs we expect for the quarters. And you’ll note the third quarter and second quarter, we were below — kind of at the low end of where we thought we’d be to maybe slightly below there. And so that pushed some activity into the fourth quarter. But yes, I think productivity from the TILs that have come online have been as expected or in some cases, maybe a touch better. But yes, as we get into next year, I think Tom was — noted on the last call that, look, we’ll exit the year at 175 MBoe in the fourth quarter. And the expectation shouldn’t be that we sort of maintain at that level throughout. That’s quite possible, as you’ve seen in the past, based on the timing of TILs that we end up with a little leg lower and then begin to build from there.

Thomas Jorden: Yes, Betty, I would just add to that, that so much of this is timing, as Shane said, and working interest changes. So there’s just a lot of moving parts. But we’re seeing very, very solid really returns and performance out of all of our assets and particularly in the new assets we acquired earlier this year, they’re coming on strong. There’s just no question in our mind as we reflect back on the last year, we’ll exit the year a much stronger company than we entered the year. And we were able to do that because of our balanced portfolio, our multi-revenue contribution to that balance and our strong and fortress balance sheet. So we’re absolutely exiting the year a stronger, better company.

Operator: And our next question comes from the line of Arun Jayaram with JPMorgan.

Arun Jayaram: Yes. Team, I wanted to see if you could provide any kind of overall commentary on your thoughts on CapEx reduction next year. You mentioned that you think it will be down moderately, but maybe help us fill in the pieces of the drivers of that, perhaps relative to your soft guide of delivering 5% year-over-year oil growth.

Thomas Jorden: Yes, Arun, I’ll start that, and somebody else may want to comment. We’re seeing good asset performance. And as we look ahead to the oil markets, we’re kind of watching what happens. I mean I think that one can make a constructive observation about the strip, but some of that is underpinned by cartel discipline, if you will, and geopolitical factors. I think in balance, if you lean back, you say the world is fairly oversupplied if everybody supplied at their full capacity. And so we want to be prudent. I mean part of our ability to lower our capital is driven by our asset performance. We can deliver on our 3-year plan guide handily. We do have the option to increase capital, as I said in my opening remarks, and step that oil growth up.

But we really do think about it in terms of cash flow and profitability rather than volumes. And one of the best ways — if you have price support in your commodity, the best way to grow your cash flow and free cash flow is to see some volume growth. But we’re watching the markets thoughtfully.

Shannon Young: Yes. Arun, I mean the only thing I would say is, in addition to that is, look, nothing’s set in 2026 yet. We’ve got a lot of flexibility as we see it today. We’d be modestly down. But I think you’re going to see us when we come out in February, deliver a highly capital-efficient plan that generates a substantial amount of free cash flow. As I noted in my earlier comments, cash flow this year was up 60% over 2023 on the back of higher oil volumes from the acquired assets as well as higher natural gas price realizations. The 2 of those contributed, and it’s a really powerful combination.

Arun Jayaram: Got it. And then maybe my follow-up, you highlighted some parts of the Franklin, Avant acquisitions that closed in 1Q, maybe exceeding your expectations. Can you talk about some of the things that you’re seeing post your review of those acquisition economics and maybe a little bit more insights on the ground game that you’ve done. I think you’re investing about $86 million in leasehold, which is driving a little bit more of an inventory improvement there.

Blake Sirgo: Yes, Arun, this is Blake. Happy to take that one. Frankly, our teams have done what we hope they do. They’ve taken this asset, and they’ve made it a lot better. Our subsurface teams are delineating. So we’re finding new zones that we didn’t account for when we underwrote it, and we’re adding net footage across the asset base. Our D&C teams are attacking the program with all of our large efficiencies we built over the years. We’re driving down dollar per foot and our production and midstream teams are attacking OpEx, and they’re dropping that as well. So we’re really just seeing those efficiencies across the board. They’re really starting to add up, and this is a great add to our portfolio.

Operator: And our next question comes from the line of Neil Mehta with Goldman Sachs.

Neil Mehta: I have a couple of gas questions here, Tom. But first, just to expand on your initial comments. I guess one of the questions we get from investors even beyond the letter this morning is what’s the value of operating as a multi-basin portfolio versus being a pure play? And so just maybe you could spend some time now that’s been a couple of years you’ve had Cabot under your portfolio. What are some examples of the tangible upsides or synergies that you get from diversification? Obviously, the commodity is one of it — but — one of them, but I’m sure there’s others.

Thomas Jorden: Yes. We’re going to need a longer call for that question. One of the advantages, odd as it may seem, even though we’re a broad industry, there tend to be regional pockets. And a lot of companies are single basin. And so techniques and operational efficiencies tend to be clustered until they get understood and widely spread. And you saw that in our history over and over. One example is the industry had gone to plug-and-perf completions, while there were still basins that were doing slotted liners way after other areas had abandoned that. You saw that with many completion techniques. And we’re actually — I’ll just say, speaking for Coterra, there’s a reason why we’re recognized as a great operator in every basin we’re in.

And that’s because we’re a multi-basin company. We can take best practices from play to play and make our programs better. A particular example I’ll give you, and you’ll see this, hopefully, in this upcoming winter because we always light a candle and hope for a bitter cold winter, we have made massive advances in winterization in the Permian Basin. We get insights to a lot of our competitors because we have interest in their wells. So when these winter storms pass through, we see the degree to which our competitor’s production is knocked offline and decreased, while Coterra tends to sail through with only a wobble. And that’s because of the collaboration we’ve had with our Marcellus team for whom cold, bitter winters are a regular event and our Permian team, and it has made us such a better operator and really strengthened our ability to sell product into winter pricing.

The list goes on and on, but I will just tell you that having collaboration among different play types really enlarges technical thinking around problem solving and has made this a better company.

Neil Mehta: And then the follow-up is just on scale. I mean, I think in the Permian, Franklin Mountain continued to give you the scale that you need to be competitive against the largest players in places like the Permian. In the Marcellus, we’ve seen a lot of consolidation here. Do you feel like you have sufficient scale to be first quartile in the Northeast?

Shannon Young: Yes. I’ll make a quick comment on that. Look, I do think we have the scale there. We produce about 2 Bs a day in a market up in the Northeast itself that’s probably closer to 11. But — and really, one of the things, just kind of building on what Tom said up there, when we negotiate with service providers when Blake and Michael sit down with them, it’s not like we’re just negotiating a frac crew for that area. So we have one active crew. We’re having a one-off negotiation because we have a broader portfolio, we’re actually able to drive down costs, get better equipment and better focus from the service providers. And so in a lot of ways, we have plenty of scale up in the Northeast. But frankly, the Northeast benefits from the larger scale of Coterra.

Operator: And our next question comes from the line of Scott Gruber at Citigroup.

Scott Gruber: I want to come back to your active ground game here. Can you talk about your thoughts around running room to block up your positions in Lea and Eddy counties and the timing of doing so in a competitive market? And just how important is that in terms of compressing your cost structure in the Northern Delaware down towards Culberson? Or do you think you have kind of a good running room to further compress costs on your current acreage position?

Blake Sirgo: Yes, Scott, this is Blake. I’ll take that. The Franklin Mountain, Avant assets really gave us a great footprint in the Northern Delaware. And what that’s allowed us to do is now have a foothold in certain areas where we can start doing trades and additional small acquisitions. And really, what we’re just chasing are the biggest DSUs we can get our hands on, more wells per section, longer lateral lengths, that’s how we drive efficiencies. And so really just building that footprint up there has kind of turbocharged our land efforts. And I couldn’t be happier with the deals the team has brought in over the year. They’re very, very busy. We look at all those with a firm economic lens. But like I said, those capital efficiencies we can bring to bear, they make a lot of them really attractive to us.

Scott Gruber: And what is your color on the ’26 budget reflects the trend in well costs in the Northern Delaware as you gain more experience on the acreage and expand the position? Does that continue to step down? Would that be incremental benefit to the spend in ’26? And does the well mix in the Delaware stay broadly the same in ’26 kind of as you see it today?

Michael Deshazer: Scott, this is Michael. Yes, we — as I mentioned in my prepared remarks, we continue to drive down the capital costs of all the wells in the Northern Delaware Basin. And so we expect our teams to continue to work hard every day to try to drive that cost down. We don’t have a projection that we’re ready to discuss here, but I did mention a lot of the same efficiencies that we see across our assets around consistent drilling rigs and frac fleets and being able to drill longer laterals. All of those benefits would be available to us in that Northern Delaware Basin and all the trades and blocking of acreage that Blake talked about really helps. The bigger these pads are and our ability to put more wells into the same facilities really helps us drive down costs on both the production side, the capital side and on our midstream side.

Operator: And our next question comes from the line of David Deckelbaum with TD Bank.

David Deckelbaum: I wanted to ask perhaps for a little bit more color just on the ’26 high-level guide of spending kind of sub $2.3 billion. How the sort of large projects impact that going into next year? Or as we think about this, is it being driven more by reallocation between basins or the inclusion of more Wolfcamp relative to what we saw in ’25? Could you add a little bit more color there just on what’s contributing to that trajectory the most? Or is it just general optimization?

Michael Deshazer: Thanks, David. This is Michael. Yes, as I — as we discussed earlier, we currently have our operations very steady across the business units, and we expect that to extend into 2026. We don’t see a lot of dramatic changes from where we’re at right now in Q4 in terms of the way we see the program into ’26. I did mention that our Marcellus would be between 1 and 2 rigs. So we’ll be making those decisions as we look at frac efficiency and drilling efficiency. And we’re really excited to see the recent results of drilling these longer laterals in the Marcellus has allowed us to reduce that rig count. So we’re not exactly focused on the resources around rig and frac as much as we are a consistent program within each of these business units from a capital perspective.

Thomas Jorden: Yes, David, I want to just add there that I’ll be a broken record, but it is a soft guide, not an announced plan. We’re still looking at some of our options. I think depending on what happens with commodity markets, though, as we look at that soft guide, probably our bias would be to maybe slightly increase over what we’re telegraphing than decrease. But we have the wherewithal, we have the projects, and we have the willingness to step in. We’re just watching carefully, and we want to be prudent in how we approach 2026.

David Deckelbaum: I appreciate that color, Tom. And maybe just following up a bit on just the cadence of the program into the ’26. You talked about sort of this 5% oil growth next year. And maybe, Michael, this one is for you, but the — can you just kind of refresh us on how you kind of see the shape of the Delaware progressing throughout the year after some pretty aggressive growth what we’ve seen in the back half of ’25?

Michael Deshazer: Yes, we’re not prepared to discuss any kind of TIL timing or that kind of granularity at this point in time.

Operator: And our next question comes from the line of Matt Portillo with TPH.

Matthew Portillo: I wanted to start out on the power opportunity in the Permian. You mentioned the microgrids. That seems like a great opportunity for you all to cut costs moving forward. I was curious if you might be able to provide a little bit more color around the timing of when those microgrids might come into service and how many megawatts you’re planning on deploying.

Michael Deshazer: Yes, Matt, this is Michael. We currently have some smaller scale microgrids that we inherited with the Franklin Mountain, Avant acquisition. I discussed in the prepared remarks that Eagle’s central tank battery has turbines located on it that are powering adjacent leaseholds. So we’re already in this business, and we’re really just looking for opportunities to expand it. As you know, the Northern Delaware Basin and really the Permian on the New Mexico side has been very constrained for power for some time. And many operators are using small reciprocal engines to generate power on a well site-by-well site basis. And where we see value is when we can connect multiple leases to a single permanent station that’s run off turbines, we see a dramatic decrease in that electrical cost.

So we’re going to continue to expand the current microgrids that we have. And like I mentioned in the remarks, we see opportunities for about 3 expanded microgrids across our asset.

Matthew Portillo: Great. And then maybe a follow-up on the Northeast. It sounds like the soft guide as it stands today at strip is for relatively flat volumes around that 2 Bcf a day. I just want to make sure I heard that correctly. But maybe over the medium term, I was hoping you might be able to comment on your updated thoughts around power demand growth regionally for Northeast PA? And then any updated thoughts on maybe some of the longer-haul infrastructure opportunities such as Constitution that had been discussed earlier in the year.

Shannon Young: Yes. So I’ll start with the second one first, which is Constitution and some of the other projects that are up there. And look, that project historically has originated out of our acreage and heads up towards the Iroquois line about 124, 125 miles. And so were something to happen there, obviously, we would be a logical partner in some regard in that. But frankly, until we have better clarity on the other end of that line in terms of markets and buyers and commitments, that’s probably one that is going to remain a little bit challenged. Obviously, there’s other projects in that part of the world, [ NeSSIE ], for example, that appear to have a little bit more momentum at this point. And we — while we wouldn’t have the same direct linkage to it, we would expect that we would benefit from development in that area as well. I’m sorry, the first question — the second question [ is something about ] the first part of…

Matthew Portillo: Just around the regional power demand growth opportunity specific to Northeast PA, just how you see that market emerging and what that might mean maybe for the opportunity to add some volumes at some point in the future from a production standpoint?

Shannon Young: Yes. That’s great. So a lot of activity in PA, a lot of announced activity, that’s preliminary, not necessarily all with definitive agreements, but with intention, which is a good first step. I think as well, there’s a lot of unannounced activity that is up there right now in terms of dialogues that are going on. I think Michael and Tom sort of alluded to our team and being a part of those conversations. And so we’re very excited about the potential up there, and we’ll continue to work it hard. Some of these projects, whether we’re involved or not, take a long period of time to develop and get announced. For example, again, not in the PA, but in West Texas, those are discussions that we have been in with CPV for the better part of 2 years.

And so these are just long lead time discussions and negotiations that are ongoing, and we have a history of involvement in all of our business units, frankly, and I would expect we’ll continue to be active in those dialogues.

Thomas Jorden: Matt, we have a lot of flexibility in our marketing in the Northeast. We’re watching carefully the development of these markets. We’ve talked about a couple of these pipelines that may offer opportunity for us. But our marketing team has done a really nice job of developing a weighted average sales price through a whole host of different arrangements. As we’ve discussed, some of that’s LNG, some of that’s direct power and some of it’s direct to industrial users. But what we really look at when we ask ourselves about growth is that incremental molecule against the incremental price. And although we study hard what some of our competitors have done, we just don’t see that now is the right time to bring on a lot of incremental volumes on that incremental price.

We’re going to be patient. We think opportunities will come, and we’ll be prepared to strike, and we have the opportunity to grow those volumes, both through increased activity, but through some of our existing commitments that roll off give us more marketing flexibility as we go forward. So we’re in a pretty nice position. And we’re — as I said in my opening remarks, we think patience and prudence is the right position right now.

Operator: And our next question comes from the line of Kalei Akamine with Bank of America.

Kaleinoheaokealaula Akamine: I want to start on the Marcellus. The deal with Cabot closed about 4 years ago, and you’ve made that position better through your operating efficiencies. So maybe you can start by calling out some key operating wins. And then when you look at the Marcellus landscape, do you think that the application of your best practices could create value through M&A?

Blake Sirgo: Yes, Kalei, I’ll take that — the first part. I’ll let Shane talk M&A. Really, how we have attacked the Marcellus, it was really fun when we got our hands around the asset because we kind of had a greenfield Upper Marcellus bench to go prosecute. And we had over a decade of developing shale basins in Oklahoma, Texas, New Mexico, and we just brought those same skills to bear. And so one of my favorite maps to look at is the inventory at the time of the acquisition and the inventory now. It is dramatically in lateral length across the asset. We’ve optimized well spacing to increase productivity. And then we’ve just attacked the entire cost value chain. When we started that asset 4 years ago, we were still trucking the majority of our frac water.

I’m really happy to say we pipe all our frac water now. And we’ve just been able to crush cost across the board. And so it’s really a lot of those best practices Tom talked about earlier. We learn all these things through a lot of grit. And once we learn them, they become institutionalized, and we spread them like wildfire.

Kaleinoheaokealaula Akamine: The follow-up question just on Marcellus inventory. I think you guys are still calling out 12 years of drilling in the slide deck. And this year, you’re doing about 11 wells. Is the inventory math as simple as [ A times B ]? And would that include any of the delineation work that you guys have done in the…

Michael Deshazer: So no, the math isn’t just the current 2025 TIL count versus that multiple of years. What we’re looking at is our 3-year average for how many wells we’ve drilled and then using that as the main proxy. We’re also converting this into dollars and trying to keep the capital spend that we’ve had over the last 3 years as the metric. As we drive down costs, we are able to drill more wells in a given period of time and keep that production at a given level, so — for the same amount of capital. So 2 things that are not as simple as what you described. One is we’re looking at 3-year average. Two, we are looking at the capital spend and adjusting for our new go-forward costs.

Operator: And our next question comes from the line of Derrick Whitfield with Texas Capital.

Derrick Whitfield: With respect to the shareholder letter, Tom, I’d like to go a different direction with it and ask for your perspective on how your PVIs compare across the basins, while we all have inverse incremental assessments, our data quality and look-back assessments are less accurate than yours, particularly on a leading-edge basis.

Thomas Jorden: Well, I think we’ve said publicly that in 2025, the highest PVIs in our portfolio coming from our Marcellus project, and we’re very happy to say that. And I just want to kind of reinforce comment Blake made in one of the earlier questions. We have made that project. Our team in Pittsburgh has made that project so much better. We’ve lowered our costs dramatically. We’ve gone to longer and longer laterals. And in many cases, that’s 4-mile laterals that involve fewer pads, fewer intrusion into the community there. And we’re seeing historically high well performance. So very pleased to say that the highest return in our portfolio this year is the Marcellus.

Derrick Whitfield: Great. And then maybe for my follow-up, I wanted to focus on gas marketing in the Permian. In light of all the recent pipeline announcements that have achieved FID and the flurry of power announcements we’re seeing, how are you guys thinking about managing your Waha exposure? And could this amount of incremental egress lead to favorable in-basin exposure if oil prices remain depressed?

Michael Deshazer: This is Michael. I’ll take that question. We have struggled in the third quarter with low Waha gas prices. I think everyone sees that. And so the long-haul pipes are important to reduce the basis between Waha and NYMEX. And we’re a part of all the conversations with the new pipes that are being announced. So we’re looking at opportunities to put some of our gas that we can take in kind on those pipes and provide ourselves not only the flow assurance that we want, but also that increase in price at that NYMEX market.

Operator: And our next question comes from the line of Phillip Jungwirth with BMO Capital Markets.

Phillip Jungwirth: I wanted to come back to some of the major projects in Culberson this year, the Barba-Row Phase 1 and the Bowler Row, see if you had any updates or takeaways as far as cost efficiencies, early time productivity. I think Barba-Row is expecting second half wells online. And I know it’s early, but Bowler starting up in the fourth quarter.

Blake Sirgo: Yes, Phillip, this is Blake. I’ll take that. Everything is coming on as expected, performing well, contributing [ mightily ] to the oil beat we just announced for Q3. Those projects are ramping up throughout the year. And we continue to enjoy the wonderful cost efficiencies in Culberson County, all the things we’ve highlighted in many previous decks. It is still the crown jewel of capital efficiency. So performing very well.

Phillip Jungwirth: Okay. Great. And then we always think of Coterra’s kind of cutting edge, willing to implement new technologies. Curious if you’ve looked at lightweight proppant, something — is this something you’d consider implementing within your Delaware development? I understand you won’t be producing this in your own refineries, but using it more — buying it more through third parties.

Michael Deshazer: Yes. We have a trial ongoing, as a matter of fact, on new lightweight proppant. So we don’t have any results to share today, but that’s a technology that we’re investigating, and we have a lot of hope to see improved productivity as other operators have discussed.

Operator: And that concludes our Q&A session. So I will now turn the call back over to Tom Jorden for closing remarks. Tom?

Thomas Jorden: Yes. I just want to again thank everybody for joining us. We had a great quarter. We’ve got a bright future, and we really intend to demonstrate the marketplace that the Coterra model is resilient through the commodity price swings, and we’re going to continue to deliver excellence as I hope we’re known for. So thank you all very much.

Operator: Thanks, Tom. And this concludes today’s conference call. You may now disconnect. Have a great day, everyone.